Generally, in the field of oil and gas exploration and recovery, analysis of seismic data obtained through seismic surveys can provide crucial physical parameters of subterranean rock formations. Conventional surface seismic surveys record compressional, or P-waves. Multicomponent seismic surveys record both P-waves and shear, or S-waves. Seismic data processing methods include azimuthal velocity correction and amplitude versus offset (AVO) analysis and inversion, amplitude versus offset and azimuth (AVOA or AVAZ—Amplitude Versus Angle and aZimuth) analysis and inversion of conventional three dimensional (3D) seismic data, and birefringence analysis of multicomponent 3D seismic data. The analyzed seismic data can provide useful information regarding the characteristics and parameters of the subterranean formation such as rock strength: Young's modulus and Poisson's ratio, and in-situ principal stress directions and magnitudes: one vertical stress, σv, and two horizontal stresses, σHmax and σhmin. Further, seismic detection of subsurface fractures has important applications in the study of unconventional rock formations such as shale plays, tight gas sands and coal bed methane, as well as carbonates, where the subterranean formations are naturally fractured reservoirs.
Information concerning these characteristics and parameters are often essential in a variety of fields such as underground transportation systems, foundations of major structures, cavities for storage of liquids, gases or solids, and in prediction of earthquakes. In oil and gas exploration, the information is important for determining optimal locations and orientations of vertical, inclined, and horizontal wells, minimizing wellbore instability, and formation break-out. Also, these characteristics are crucial to optimize the operating parameters of a commonly utilized technique for stimulating the production of hydrocarbons by applying hydraulic pressure on the formation from the wellbore.
Conventionally, the rock strength parameters and in-situ principal stress magnitudes have been obtained by testing the core samples and these physical parameters have been calculated by testing the core samples, which are extracted from an oil or gas well in a manner known in the art, by applying forces to core samples and measure responses to such forces. In-situ stress directions have been assumed to be equal to the direction of the regional stress field, determined either from nearby borehole ellipticity or from the “World Stress Map,” which is a global database of recent tectonic stress in the Earth's crust. The database is an open-access database and is available through various sources.
These methods, however, fail to consider large-scale vertical fracturing and lateral variations in such fracturing within the subterranean formation. The preferential orientation of the vertical fracture networks, in conjunction with the present-day subterranean stress field, causes the formation to be an azimuthally anisotropic medium with respect to seismic wave propagation in seismic surveys, thereby affecting seismic amplitude and velocity. Wide patch or wide azimuth recording in which a wave velocity changes with direction of propagation has frequently been used to acquire 3D seismic data on land. Offset distribution and azimuth sampling in such recordings have not been a priority. As such, the resulting offset and azimuth sampling is often inadequate for reliable measurement of crucial azimuthally variations.
In addition, these methods known in the art for estimating the necessary rock strength parameters and in-situ principal stress directions yield results that do not match the field measurements of in-situ stress. Further, the results from these known methods are spatially restricted, meaning the models are localized to only the area where the data was gathered. Thus, the models produced by these known methods would be inaccurate and unreliable for unconventional rock formations such as shale plays, where the rock strength and stress can vary significantly over a few hundred meters.
Although various data analysis methods that consider the anisotropy characteristics, such as AVO, LMR, joint and simultaneous inversion, and multicomponent analysis, have been employed to estimate the rock strength parameters from seismic data, these have not previously been used to estimate the three principal stresses. For instance, the disclosure in Goodway et al., 2006, “Practical applications of P-wave AVO for unconventional gas Resource Plays—I: Seismic petrophysics and isotropic AVO” CSEG Recorder, pp. 90-95 suggests a method of estimating closure stress, based on an equation by Warpinski. Closure stress is generally thought to be equal to the minimum horizontal stress, which is only one of the three principle stresses estimated by this invention. The current invention is substantially different from that of Goodway in that it estimates all three principal stresses, rather than just the closure stress. Furthermore, the present invention provides for a new and innovative way of estimating the principal stresses by modifying the concepts of Iverson, W. P., 1995, “Closure Stress Calculations in Anisotropic Formations” SPE Paper 29598 (hereinafter “Iverson”) to incorporate anisotropic elastic properties derived from Schoenberg, M. and Sayers, C. M., 1995, “Seismic anisotropy of fractured rock” Geophysics, 60, 1, pp. 204-211 (hereinafter “Schoenberg and Sayers”), rather than merely estimating closure stress using Warpinski.
In addition, while azimuthal AVO analysis has been used in structural interpretation such as to identify the presence of fractures between well locations, the reliability of this method is limited to situations where the seismic anisotropy is caused by fluid-filled fractures, there is a single dominant fracture set, the fracture set is near vertical, and the fractures are connected. Further, the azimuthal AVO method does not provide for a simple way to estimate the principal stresses from seismic data. Another known method, multicomponent fracture analysis, similarly does not provide for a simple estimation of the principal stresses, which are crucial in the oil and gas exploration and development.
The novel approach of the present invention overcomes these problems associated with methods known in the art. For example, the present invention estimates the in-situ principal stresses from anisotropic elastic properties of the subterranean formation, which are derived from seismic data through the use of the linear slip theory. As such, the principal stresses can be estimated from seismic data. Further, the present invention can be used to estimate density between wells that allow for the calculation of vertical stress, σv, between wellbores. Furthermore, the present invention allows for calculation of a Differential Horizontal Stress Ratio (DHSR), where
      DHSR    =          (                                    σ                          H              ⁢                                                          ⁢              max                                -                      σ                          h              ⁢                                                          ⁢              min                                                σ                      H            ⁢                                                  ⁢            min                              )        ,from the seismic parameters alone, without any knowledge of the stress state of the subterranean formation. That is, the present invention allows for identification of the areas that will be optimal for hydraulic fracture stimulations without the need to know the vertical stress.
In addition, the present invention also provides a simple relationship between horizontal stresses, σHmax and σhmin, and vertical stress, σv, such that they can be easily calculated from the results of seismic simultaneous or joint inversion and azimuthal AVO inversion. Also, the present invention allows for the calibration of the horizontal stresses, σHmax and σhmin, to a known reference point by introducing a tectonic stress term. Furthermore, known methods of estimating the vertical, or overburden stress, often use well logs that are almost never acquired all the way to the surface. The present invention allows an improved estimate of the vertical, or overburden stress, by using simultaneous or joint AVO inversion of prestack seismic data, which can provide density values all the way to the surface and can incorporate surface topography.
In view of the drawbacks of methods known in the art for determining in-situ principal stresses and rock strength, there is a great need for reliable and accurate estimation and dynamic modeling of the rock strengths and principal stresses of subterranean formations. The present disclosure provides for methods and systems that produce reliable estimates of principal stresses, particularly for large areas between wellbores, from well known extraction techniques of seismic data.